As the oil and gas industry are going to deeper water inadvertent gas entry into the drilling riser is a challenge due to that the high static pressure at the seabed causes the gas to be highly compressed and in dense phase. Another challenge is that due to the static high pressure and low seawater temperature any gases that may enter the wellhead, subsea BOP, riser annulus and K&C (kill and choke) lines may form hydrates. Hydrates can form if gas and water are both present and the pressure is relative high and temperature relative low. Hydrates have a strong tendency to agglomerate and to adhere to the pipe wall and thereby plug the pipe or riser annulus.
There are known several case stories on how hydrates have caused problems during deep water drilling and well control operations. In 1989 an SPE paper was published with two case stories with formation of hydrates during deep water drilling operations.
SPE paper 16130-PA; Formation of Hydrates During Deepwater Drilling Operations. Authors: J. W. Barker, SPE and R. K. Gomez, SPE, Exxon Co. U.S.A. Journal of Petroleum Technology, March 1989.
Case 1. US west coast 1,150 ft (350 m) water depth, temp. 45° F. (7° C.) at mudline.                Gas from a sand formation at 7,750 ft (2362 m), was channelling up through a primary cement column and migrated up the (7″×9⅝″) casing annulus.        The wellhead hanger packer was leaking, allowing the migrating gas to enter the freshwater mud at the subsea wellhead.        After the conclusion of the kill operation, approximately 7 days after gas was first detected, both the choke- and kill line were found plugged.        After cementing operations, which secured the wellbore, the BOP stack was recovered. Hydrates and trapped gas were found in the choke- and kill line for the bottom eight riser joints.        
Case 2. Gulf of Mexico 3,100 ft (945 m) water depth, temp. 40° F. (4° C.) at mudline.                After drilling to 7,679 ft (2340 m), the well was found flowing during a flow check.        During the attempt to establish circulation after shut-in, returns could not be established and casing pressure fell to zero.        Fourteen hours after the kick was first detected, all BOP's were opened to observe the well, which appeared static.        Almost 30 hours after initial shut-in, the well flowed again and the BOP's were closed. Part of the gas influx above the closed BOP's continued to migrate up the riser and was successfully diverted.        The choke-line was determined to be plugged during subsequent attempts to circulate mud (down the choke-line and) up the riser above a closed ram-type BOP.        The kill line also may have been plugged because it was not checked at this time.        With no apparent well pressure the, the BOP's were again opened to monitor the well.        Almost 48 hours after the initial well kick, the well flowed a third time. After an annular BOP was closed, the lower middle ram-type BOP was actuated to prepare for drillstring hangoff; however, it did not take the proper amount of closing fluid.        The lower most ram-type BOP was then closed.        The riser continued to flow mud and gas that was successfully diverted overboard.        During subsequent attempts to fill the riser, the kill line was determined to be plugged.        During pulling of the riser and BOP's, hydrates were recovered from the choke-line and the kill line of the bottom riser joints.        Testing of the BOP's at the surface indicated that failure of the ram-type BOP's to open fully or close fully on the ocean floor was not caused by mechanical failure or problems in the BOP control system.        
Barker and Gomez have stated in 1989 based on the two cases above that; “Formation of natural gas hydrates during deepwater well-control operations can have several such adverse effects as:                1) Choke- and kill-line plugging, which prevents their use in well circulation.        2) Plug formation at or below the BOP's, which prevents well pressure monitoring below the BOP's.        3) Plug formation around the drillstring in the riser, BOP's, or casing, which prevent drillstring movement.        4) Plug formation between the drillstring and the BOP's, which prevents full BOP closure.        5) Plug formation in the ram cavity of a closed BOP, which prevents the BOP from fully opening.”        
Although the challenge with hydrates during drilling and well control operations has been known for many years, several cases with hydrates causing problems have also been reported after 1989.
A potential plug in the riser annulus is dangerous because if the BOP is closed in and the booster pump is used to circulate out the gas hydrates from the riser, the applied pressure from the booster pump may burst the drilling riser. It is also dangerous if liberated gas from above the plug may displace the liquid mud above and create a chain reaction creating a large differential pressure across the plug. If the hydrate plug for some reason then becomes loose it may accelerate up the riser fast and potentially plug all riser outlets as a secondary effect. An accelerating hydrate plug up the riser annulus may also release large amount of gas, increasing the pressure in the riser. This may then create an overpressure that may burst the slip joint or flow hoses in the upper part of the riser (in case of managed pressure drilling technics are used), resulting in a large gas release in the moon pool area.